Patrick Crow
Washington Editor
A. D. Koen
Gulf Coast News Editor
A tighter fit between supply and demand in U.S. gas markets is boosting spot market and futures contract prices to unexpected levels, sustaining a year long rally.
Market balance and higher wellhead prices have been awaited for the past decade as signs that a gas industry recovery could be under way.
But a slim gap between gas supply and demand could portend adversity as much as advantage. And if prices increase too much, too fast, as much damage as good will be done to the still ailing U.S. gas industry.
The country's gas demand continues to grow, with consumption this year expected to top 20 tcf while the supply picture dims. At the start of the year, surplus productive capacity had slipped to 5.2-6.3 bcfd, the lowest in a decade, and utilization was about 90%, Energy Information Administration estimates. Despite a weak Gulf of Mexico drilling rally, U.S. gas well starts through first quarter 1993 probably will not be enough to halt the decline of gas reserves or productive capacity.
Concern that today's market balance could be fleeting is heightened because colder than expected weather late in the heating season reduced working gas in storage to unusually low levels. Thus, companies refilling storage to serve markets next winter will scramble for supplies, likely underpinning unseasonally high gas prices during the summer.
If industry has not adequately refilled storage by Nov. 1, when interstate gas sales and transmission lines are to be operating fully under Federal Energy Regulatory Commission Order 636, some observers predict brief, local shortages.
That could cause industry problems even as the long-sought higher prices materialize as a result. Reliability of service has become a concern for the natural gas industry because it is a concern for consumers.
An extensive National Petroleum Council (NPC) study recently concluded natural gas can make a greater contribution to the nation's energy supply and environmental goals (OGJ, Dec. 28, p. 106). More than a year ago, the major gas associations formed the Natural Gas Council (NGC) with the goal of increasing U.S. gas demand by 2.5 tcf by 1996. Last fall an Energy Department-Federal Energy Regulatory Commission study on gas deliverability called for a better information system to report on the deliverability of gas supplies (OGJ, Sept. 28, 1992, p. 102). In January, NGC created a task force to establish the Natural Gas Reliability Council (NGRC) to enhance gas service and increase customer confidence.
PRODUCTIVE CAPACITY
EIA concluded Lower 48 dry gas productive capacity will continue to decline sharply through 1993 under each of three price and drilling scenarios.
In the low price/low drilling case, EIA predicts U.S. wellhead productive capacity would decrease by 16% from December 1991 to December 1993. In the base case, the decline would be 12%, and with higher prices and drilling activity, the drop would be 8%.
Gas prices for the low, base, and high cases are $1.73/Mcf, $1.97/Mcf, and $2.18/Mcf, respectively, in 1993.
In EIA's low case, surplus U.S. dry gas wellhead capacity drops to 1.2 bcfd by December 1993, in the base case to 3.7 bcfd, and in the high case to 6.1 bcfd-54% less than in December 1991. In the base and high cases, monthly productive capacity should be adequate to meet demand.
To halt the slide in productive capacity, gas well drilling and completions must increase substantially beyond levels in 1992, EIA said.
EIA also concluded:
- Adequate monthly productive capacity can be maintained after 1993 if enough wells are drilled and demand continues to rise moderately.
- Under the low price/low drilling case, Texas and Gulf of Mexico federal waters-the two largest U.S. gas producing regions-are not expected to maintain their historical shares of U.S. gas output.
- Under the base price, base drilling case, Texas will not maintain its historical market share by late 1993.
SHORTAGES FEARED
While low gas prices before 1992 spurred demand, volatility the past 13 months has discouraged operators from spudding gas wells not tied to federal tax credits. That has crimped U.S. productive capacity.
Last month in Austin, Stan McLelland, executive vice-president of Valero Energy Corp., San Antonio, testified before the Texas Railroad Commission (TRC) that U.S. gas consumption the past year was 22% more than consumption in 1986 and this year is expected to top 20 tcf -an average of 55 bcfd.
Meantime, however, average U.S. peak monthly productive capacity has fallen to 51-52 bcfd and production to 48-49 bcfd, or about 18 tcf/year. The domestic shortfall largely has been offset by increasing imports of Canadian gas. But even the upper limits of Canadian gas export pipeline capacity are beginning to be tested, McLelland said.
C. Russell Luigs, chairman of Global Marine Inc., Houston, estimates utilization of U.S. gas wellhead capacity this year at closer to 99%, up from 83% in 1986-87. Speaking earlier this month at a marine and offshore industry conference sponsored by Texas A&M University's Sea Grant program, Luigs said U.S. gas buyers have been able to rely on spot markets while federal regulations have been evolving because of a substantial surplus of U.S. productive capacity plus Canadian imports. But with U.S. gas consumption continuing to increase, while "U.S. gas wells are producing wide open for all practical purposes ... (and) Canada's ability to export gas into the U.S. is becoming saturated," smoothly functioning gas markets are no longer assured.
Luigs said as supplies diminish, U.S. spot market gas increasingly will be available only on a price allocated basis.
"There will be less gas available immediately than is needed to serve the call, and buyers willing to pay the most will be served first," he said. "That's the sort of thing that tends to lead a bunch of misguided bureaucrats to start down the road toward reregulation."
DEPRESSED DRILLING
Higher gas prices have spurred a minirecovery of drilling activity in the Gulf of Mexico. But the decline in the number of rigs drilling gas wells onshore has more than offset the gain offshore.
After sliding to a low last year of about 60 mobile offshore drilling units (MODUs), about 105 MODUs were under contract in the gulf in mid-April. In first half 1992, the number of rigs drilling gas wells in the U.S. bottomed out at 242 units, By the end of 1992, operators trying to drill unconventional gas wells qualifying for Section 29 U.S. federal tax credits led the number of rigs working on gas wells to 528, as counted by Baker Hughes Inc., Houston. In its tally for the week ended Apr. 16, it counted 262 rigs drilling gas wells in the U. S.
David A. Herasimchuk, vice president of market development for Global Marine, said that with gas prices up substantially since early 1992, more rigs should be drilling.
For example, in 1988-90-while gas prices averaged about $1.60/Mcf, the average number of rigs drilling in the Gulf of Mexico was about 140.
"Right now, we've got $2.35/Mcf gas and only 105 rigs under contract in the gulf," Herasimchuk said.
He attributed U.S. operators' reluctance to drill gas wells to confusion caused by pending implementation of Order 636 and a lack of long term sales contracts. Order 636 is contributing to confusion because it shifts responsibility of assuring adequate gas supplies from interstate pipelines to customers.
"End users right now are visiting interstate pipelines and looking over supply contracts in place to see which ones they can assume," he said. "When they get to the end of that process, a number of local distribution companies likely will discover they don't have enough reserves under contract. At that point, their only option is to go to suppliers and sign contracts for long term supplies."
Once producers have long term contracts in hand, they'll be willing to drill more gas wells, he said. "But until then, small independent producers generally are not going to be able to make long term investments based on short term contracts."
In addition, because major U.S. integrated companies have put a lot of domestic properties up for sale, many independents have been able not only to replace reserves but to increase reserves and production without drilling.
"From a company point of view, that solves a lot of problems," Herasimchuk said. "From a national point of view, we've got a problem."
DRILLING OUTLOOK
Whether U.S. wellhead productive capacity will decline to dangerous levels during 1993 is open to question.
According to his calculations, Herasimchuk estimates 1,100-1,200 oil and gas wells/year in the Gulf of Mexico would maintain the region's reserves. About 130 rigs each drilling about 7.3 wells/year could reach that total.
"But in the early 1980s," he advised, "the average number of wells per rig per year in the gulf really was closer to six.
Of course, the actual number of rigs needed would vary, depending on drilling results. "But it is substantially more than 100," Herasimchuk said.
However, so many MODUs have left the gulf for other provinces, some questions exist about whether enough units remain to achieve the level of drilling activity needed to maintain reserves and production.
While overall drilling activity in the gulf has been essentially flat since the first of the year with 100-105 rigs under contract, Baker Hughes has recorded a substantial increase in the share of new gas well starts.
"At the beginning of 1993, gas directed drilling accounted for about 47% of active MODUs in the gulf, we're now up to about 70% gas directed drilling," said Gary R. Flaharty, manager of market research at Baker Hughes. "I think we'll probably hold at the 70% range until late May, and in early June that percentage will start to increase.
"It could happen a little sooner. But the number of rigs under contract hasn't taken off, yet."
Baker Hughes also expects overall U.S. offshore drilling to increase gradually in 1993 but not to levels that could halt the decline of gas well productive capacity. Noting an average of 68 MODUs drilling oil or gas wells in the gulf in the first quarter, the company projects an average 70 gulf rigs in the second quarter, 77 in the third, and 82 in the fourth. In first quarter 1994, the average number of MODUs working in the gulf will drop back to 77, Baker Hughes predicts.
Baker Hughes' count of rigs drilling usually amounts to about 67% of the rigs under contract. That works out to about 105 units under contract in the second quarter, 115 in the third, and 122 in the fourth.
If the historical relationship between active rigs and rigs under contract holds through 1993, by fourth quarter utilization could be about 90%, Flaharty said.
"That would suggest operators in the gulf are going to be pretty tight on rigs during the second half of the year," he said.
THE ROLE OF STORAGE
With winter peak month demand reaching as high as 70-80 bcfd, the U.S. gas industry needs about 3.3 tcf of working gas in storage by early November to balance winter supply and demand.
During 1980-91, EIA estimated working gas in storage at the end of March at an average 1.765 tcf and by the end of the following October at 3.259 tcf. That works out to an average seasonal fill of 1.494 tcf. Comparable averages during 1988-92 were 1.756 tcf of gas in storage in March and 3.315 tcf by the following October, for an average fill of 1.559 tcf.
McLelland at the TRC hearing reported U.S. working gas storage as of Mar. 11 stood at 1.44 tcf. By the end of March, EIA estimated working gas in storage at 1.362 tcf, 403 bcf lower than the 12 year average ended March 1991 and 394 bcf less than the 5 year average ended March 1992.
Assuming no further significant withdrawals of working gas in April, to restore U.S. working gas storage by the end of October 1993 to the 5 year average as of October 1992 of 3.315 tcf, U.S. gas companies must inject 1.953 net tcf of gas into storage, an average of about 9.13 net bcfd. Net working gas injections during Apr. 1-Nov. 1 in 1988-92 averaged 7.29 net bcfd and in 1980-91 averaged 6.98 net bcfd.
Though he cited older data in TRC testimony, McLelland said if U.S. dry gas production this year is near output of a year ago, U.S. gas supplies from April through October could fall short about 5 net bcfd, as the industry tries to refill storage to accommodate peak demand next winter.
"Obviously, a 5 bcfd shortfall will not occur," he said. Instead, gas production likely will stay at maximum capacity during most of the year and some fuel switching could occur.
"But certain periods of downtime for repairs and maintenance-particularly with offshore production-are inevitable," he said. "For fuel switching to occur, gas prices will have to rise to levels at or above their equivalent BTU value with residual fuel oil."
STORAGE ADEQUACY
John Esslinger, president and chief operating officer of Enron Gas Services, Houston, said unusually low levels of working gas in storage as markets emerge from heating season are not necessarily cause for alarm about supplies.
As gas markets have evolved, players have begun using storage in new ways. Since gas storage is used differently today than in recent years, the significance of working gas volumes on hand isn't necessarily the same as before. Also, because interstate pipelines in the past each developed storage independently to fit system needs, Esslinger said a case could be made that there is too much gas storage capacity in the U.S.
Many companies-including Enron-still are storing gas to serve weather sensitive winter demand. But many companies traditionally served with gas from storage today either are making their own supply arrangements or are looking at alternate fuels.
"I think we haven't seen yet how storage is going to settle out in the long term," he said.
Esslinger said most large industrial companies today buy their own gas, so LDCs have no reason to store gas to serve those customers as they have in the past. Many industrial customers capable of using alternate fuels could choose to store oil rather than gas for protection against cold weather.
"Certainly, players that were storing gas to arbitrage winter-summer price differentials have lost that advantage, so they're not doing it anymore," he said. "So I don't know that we've got a good handle on how much storage is needed, and to say it looks as if there is going to be a shortage because storage this year is not going to be filled to the same levels as in the past-I can't make that leap. This industry has a habit of taking the past 5 min experience and extrapolating it 25 years."
SUPPLY RELIABILITY CONCERNS
NPC contends industry's greatest challenge is to overcome consumers' perceptions of potential gas shortages.
While regulatory burdens and supply underestimates have contributed to such perceptions, NPC noted there have been several cases where natural gas proved unreliable for U.S. customers, such as curtailments in the 1970s and the extraordinary cold period in late 1989, it said.
NPC criticized the gas industry as not being sufficiently customer oriented.
"In the past, natural gas marketing consisted of passing a commodity down the chain in the general direction of the end user, where all the commercial relationships had extensive regulatory limitations and natural gas was 'marketed' by taking orders.
"Now, many natural gas companies are playing integrated energy service roles all along the line from producer to end user. Companies that can add value to the process need to develop additional marketing capabilities that are critical to a successful natural gas industry future.
"Reliability has different meanings to different people, and perceptions are often as important as facts and analyses. It is therefore imperative that industry openly addresses the reliability issue to ensure that natural gas is best able to compete effectively in the nation's energy markets."
Richard Farman, chairman of Southern California Gas Co. and Natural Gas Council chairman, said the NGRC "can provide a valuable assurance to our customers and the public that natural gas is a reliable fuel."
Farman said as a first step, the NGRC task force will demonstrate the gas industry is a reliable energy supply for existing and new gas customers. And it will establish a mechanism for rapid response to any temporary supply disruptions, facilitate communications and deliverability data availability within the industry, and develop a communications program to explain the reliability effort.
David Biegler, chairman of Lone Star Gas Co., heads the task force. It includes two members each from the producer, pipeline, and distribution segments of the industry and one from a gas marketing organization.
The task force is planning the first meeting of the reliability council.
AMPLE SUPPLIES
American Gas Association predicts gas will increase its share of the U.S. energy market to as much as a third by 2010 from the current 25%.
AGA said supply and demand will increase to 26.34-28.3 quadrillion BTU by 2010, up 30-40% from 1992 levels.
James Cordes, Coastal Corp. executive vice president and chairman of AGA's supply/demand committee, said, "The gas resource base is vast and diverse. Sufficient and reliable supplies will be available at competitive field prices in 2010 in the range of $2.50-3/Mcf in 1993 dollars to continue to supply growing demand. Much of the growing resource available at moderate costs is a result of advances in gas supply technologies."
AGA said domestic gas production is expected to account for 85% or more of total U.S. gas supply through 2010 vs. 88% today. It noted that all the studies on gas supplies are optimistic about the potential of the resource.
Copyright 1993 Oil & Gas Journal. All Rights Reserved.
